February 10, 2011
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№ 1 (January 2011)

Shale Gas: Great Expectations, Modest Plans

   Shale gas is a name for methane contained in highly сlayish layers:  aleurites, argillites and shales. Such deposits have long been known to exist. In 1981, just as the United States approved the Windfall Profit Tax Act, limited gas influx was received from the thick aleurite layer on the Barnett Shale field in Texas. But then, at gas prices of $56-70 per 1,000 cubic meters (Fig. 1), low debit rates ensured production was unprofitable.

By Andrei Korzhubaev, Alexander Khurshudov

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   Shale gas deposits occupy large areas but are at extremely low permeability – thousands times lower than in conventional gas deposits. For this reason, shale deposits are classified as unconventional reserves, just as the case with coalbed methane and tight gas sandstone. In our view, the correct term would be hard-to-recover gas resources.

   Specialists often operate on a different concept which leads to great differences in their estimation of resources and reserves of shale gas. Total possible resources of our planet are estimated at 200 trillion cubic meters. To explore these hydrocarbons, some 30-50 years will be required; with that, the actual digit for gas in place is likely to be 1.5-3 times below the forecast. However, the trickiest question is to determine which resources can be classified as proved reserves, that is, suitable for profitable development.

   There is practically no experience globally on developing shale gas deposits. In 2008, U.S. EIA estimated the country’s proven reserves at 866.3 billion cubic meters of shale gas, but then announced that the methodology of the reserves count was imperfect. In our view, that there are two main reasons for that. The first is that shale gas is not located within layers bordered by water below and some kind of cover layer above; this means that conventional reserves estimation methods are impossible. Reliable estimate would require dense grid-drilling over vast deposit areas, which is unrealistic from the economic perspective. The second reason is that density and thermal value of shale methane is more than twice below that of conventional gas. Simply estimating the amount produced does not reflect its utility value; shale gas should have been counted in tons, but this is not the custom. Some authors use cubic feet of gas equivalent (cfe). In December 2010, U.S. EIA reported that U.S. proved shale gas reserves at the end of 2009 totaled 1,637 billion cubic meters. In terms of heating value that amount approximately equals 800 billion cubic meters of conventional gas.

   Outside the United States and Canada – in Europe, the Asia-Pacific region and Australia – shale gas exploration is just beginning. Very rough estimates can be made only by comparing geological similarities with North American reservoirs. We estimate that after doing all the exploration work, the value of proven global shale gas reserves (considering environmental, technological and economic limitations) will not be higher than 12 trillion cubic meters.

   The recent rapid growth of developing hard-to-recover U.S.-based gas reserves is initially due to the depletion of the richer deposits. In the 1990’s, the growth of proved gas reserves settled on the 4.5 trillion cubic meter mark; growing consumption was offset by 270 percent growth in imports. It was then that Royal Dutch Shell started its LNG projects in Algeria, Nigeria, Qatar, Mexico and Russia. In 2005, the U.S. government once again took strong measures to stimulate its domestic natural gas industry. Gas production taxes were drastically cut and authorities simultaneously increased mandatory contributions to landlords by 25 percent, prompting easier contracts with mining companies. Technical innovations such as the full-scale deployment of horizontal drilling and multi-stage hydraulic fracturing came in good time. As a result, over a four-year period shale gas production rocketed from 9.8 to 54.6 billion cubic meters a year.

   The longest shale gas production project is the Barnett Shale deposit in northern Texas. The methane-bearing layer of this field is situated at the 450- to 2,000-meter depths and covers 13,000 square kilometers. The thickness of the layer varies from 12 to 270 meters.

   The project development plan envisioned reaching a planned production level of 36.5 billion cubic meters a year by drilling over 20,000 wells on a grid with one well per 64 hectares of land. These indicators have not been achieved. In 2006, 6,080 wells produced 20 billion cubic meters of gas; in late 2008, the number of wells almost doubled to 11,800 without significant impact on 2009–2010 production.

   Gas production technology is based around drilling wells with horizontal sections of up to 1,200 meters and multi-stage hydrofracturing. As the influx depletes, the hydrofracturing process is repeated many times. The first fracing operations required about 1,000 tons of water and 100 tons of sand. Now horizontal wells costing $2.6-3 million each require about 4,000 tons of water and 200 tons of sand for each operation. On average, three operations are performed on each well every year.

   Chesapeake Energy, a major project operator, has repeatedly announced launching new wells, with the output of 350,000 cubic meters per day during the first month. However, this production rate decreases rapidly and must be supported by new hydrofracturing operations. In this case, the average yield of wells at the field is only 6,260 cubic meters per day, i.e. 56 times below the initial flow rate.

   Chesapeake Energy has been busy buying up mineral rights from landowners and in 2009 owned the licenses to an immense area of 13,600 square kilometers. About 21,250 wells are required to obtain all the gas from such area. But the growth of gas supplies to the U.S. Market reinforced by the economic crisis crashed domestic prices. In 2009, producer prices fell over 50 percent to $137 per 1,000 cubic meters, making further production unprofitable. To pay off debts of $12.3 billion, the company is trying to sell some licenses and is diversifying its business and entering alliances. And yet according to 2009 results, depreciation and asset disposal turned $7.7 billion annual revenue into a $9.3 billion loss. The company’s share of gas production at the Barnett Shale project fell from 12.4 billion cubic meters in 2005 to 6.5 billion cubic meters. XTO Energy, another shale gas producer, after studying the environment chose to merge with Exxon Mobil.

   The largest U.S. gas project, Marcellus Shale is still in its infancy. This huge layer which varies in thickness from 8 to 80 meters stretches from New York to Tennessee. It has a total area of 140,000 square kilometers and a layer depth of 700-3,000 meters. Various estimates pin geological gas reserves between 4.5-15.2 trillion cubic meters, which corresponds to gas concentration of 0.32-1.0 percent  in the layer. The gas recovery factor is presumed to be 0.1. To develop this deposit, companies must drill from 100,000 to 220,000 wells costing $3-4 million each. This puts the capital investment in well-drilling above $300 billion, or at $197 per 1,000 cubic meters.

   Huge investments are needed because the shale gas is a highly dispersed natural resource. The average density of recoverable reserves at Marcellus Shale is 3.5-10 million cubic meters per square kilometer. An ordinary gas well produces this volume for the month, a highly productive one – within a week. And both wells remain operational for at least 15 years.

   This means that full implementation of Marcellus Shale project is absolutely unreal for now; production will involve high yield plots, the rest will stay dormant waiting for better times. With operating costs on shale gas production at $80-150 and amortization costs of $100-200 per 1,000 cubic meters, full-scale implementation projects requires commercial prices of at least $350-500 per 1,000 cubic meters.

   Nevertheless, the hyped media talk on the “projected” reserves sparked tremendous global interest to shale gas exploration. In Canada, the Horn River and Montney projects are in their development stages and promising areas have been identified in British Columbia, Alberta, Saskatchewan, Ontario, Quebec; resource estimates range from 2.4 to 28 trillion cubic meters. In China, shale fields are divided into four major provinces with total potential resources of 21-45 trillion cubic meters.

   Prospective areas include the Baltic basin in Poland, in the Paris basin in France, in the Cooper Basin in Australia. Shale rock deposits have been discovered in North Africa (Algeria, Morocco), South America (Colombia, Venezuela), Russia.

   In 2010, nine shale gas exploration projects were launched in Europe (five of those in Poland). There, exploration well drilling costs $20 million. The first gas was received from a depth of 1,620 meters in Markowola-1 well. Considering that information does not specify the yield rate, the inflow was remissive. Michal Szubski, president of Poland’s state-owned PGNiG, said that the first exploration results were “not very good” though he still believes in the prospects for shale gas.

   Conditions for shale gas production in Europe are very different from conditions in America. There are no low-pressure gas networks for seamless delivery of gas to the end consumer. In Europe shale layers are located deeper and population density is higher, resulting in higher rental and land restoration costs. Meanwhile, no other oil and gas production technology impacts nature as much as shale gas production. Suffice it to say that to produce one ton of shale gas, a producer needs to inject at least 100 kilograms of sand and 2 tons of water.

   But the main setback for large-scale deployment of shale gas wells is their short lifespan. Shale gas production rate depletes within 5-10 years; to maintain the gas production level a company is forced to continuously drill new wells linking them with gas pipelines. This is unlikely to please the residents of Austria or France, who enjoy considerable revenue from tourism.

   Four exploration projects have been launched in China. However, CNPC is not that excited: it plans to edge up to 0.5 bcm per year by 2015, boosting production rate to 15 billion cubic meters per year by 2020 and to 30 billion cubic meters per year in the long run. These estimates are based on ultimate geological and technological limits, with no consideration given to environmental, economic or social factors. In our view, shale gas production in China in 2020 will not top the 5-7 billion cubic meter mark.

   The table above shows our shale gas production forecast (bcme) for the next 20 years, with due consideration of all discussed conditions. 
Spiraling growth in U.S. shale gas production in the beginning of the millennium is largely due to shortage of high profitable reserves, business activity, governmental policies and high gas prices. Sizeable money was invested in shale gas production at the time when annual average commercial price was exceeding $400 per 1,000 cubic meters. 

   However, huge capital intensity of the gas industry makes it sensitive to price fluctuations and means that price regulator is required. In many countries regulatory watchdogs are the state-owned gas companies; in the United States and possibly in Europe this function could be taken by transnational giants. With assets across the globe, large transnationals have an adequate safety margin to cut down production of difficult reserves, forcing gas prices to an acceptable level. We expect this process to take two to three years; shale gas production is set to expand once gas wellhead prices increase to $250-300 per 1,000 cubic meters. However, this expansion is likely to be a gradual, rather than quick, process.

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